In-situ combustion (ISC) processes are utilised for the purpose of recovering petroleum from heavy oil, oil sands, and bitumen reservoirs. In the process, oil is heated and displaced to a production well for recovery. Historically, in-situ combustion involves providing spaced apart vertical injection and production wells within an underground reservoir. Typically, an injection well is located within a pattern of surrounding production wells. An oxidant, such as air, oxygen enriched air, or oxygen, is injected through the injection well into the reservoir, allowing combustion of a portion of the hydrocarbons in the reservoir in-situ. The heat of combustion and the hot combustion products warm a portion of the reservoir adjacent to the combustion front and displace hydrocarbons toward offset production wells.
One of the challenges associated with existing ISC processes is that cold hydrocarbons surrounding a production well can be so viscous as to prevent warmed and displaced hydrocarbons from reaching the production well, eventually quenching the combustion process. Another challenge of traditional ISC processes is that petroleum reservoirs are heterogeneous, and therefore preferential pathways for a combustion front develop, invariably leading to combustion front breakthrough into one of the production wells before the others. The impact of this is that overall oil recovery from the pattern of injection and production wells is generally quite low.
The traditional application of ISC has been with a Fire Flood conducted using a pattern of vertical wells drilled into the target oil reservoir. Various patterns, including 5-spot, 7-spot and 9-spot, have been attempted.
An alternative implementation of the ISC technique is the application of a line drive from a row of injectors to a row of producers. Such ISC line drives have been successful in only a few reservoirs. For example, where an ISC line drive has been successful the key ingredients for success have been attributed to (i) reservoir dip (allowing oil warmed around the injection well to flow via gravity to the production wells) and (ii) keeping the spacing between injector and producer wells relatively low (A. T. Turta, S. K. Chattopadhyay, R. N. Bhattacharya, A. Condrachi and W. Hanson, “Current Status of Commercial In Situ Combustion Projects Worldwide”, Journal of Canadian Petroleum Technology, v46, n11, pp 1-7, 2007).
Various implementations of the ISC technique, such as the “toe heel air injection” (THAI) process (U.S. Pat. No. 5,626,191; T. X. Xia, M. Greaves, A. T. Turta, and C. Ayasse, “THAI—A ‘Short-Distance Displacement’ In Situ Combustion Process for the Recovery and Upgrading of Heavy Oil”, Trans IChemE, Vol 81, Part A, pp 295-304, March 2003), call for the use of horizontal production wells to provide a conduit for displaced hydrocarbons to flow from a heated region to a production wellhead. The THAI process relies on the deposition of petroleum coke in slots of a perforated liner in the horizontal section of a production wellbore behind the combustion front. However, should the coke deposition not take place or not be deposited evenly enough to seal off the liner, the injected oxidant is able to short-circuit between injection and production wells, bypassing the combustion front and unrecovered hydrocarbons.
Additionally, the THAI process incorporates vertical injection wells, so that the path of injected oxidant is very much affected by reservoir permeability distribution. As a result, performance in field trials illustrates that the formation of a well-developed combustion front that is effective in mobilising oil to the horizontal production well is difficult to achieve at commercial scale.
Field results from THAI projects show that the combustion front moves very slowly through the reservoir and that mobilised oil rates are typically in the order of 20 to 80 bpd per production well, with air oil ratios (AORs) of over 5,000 m3/m3. In several wells cumulative AORs were above 10,000 m3/m3 (Petrobank Energy and Resources, “2011 Confidential Performance Presentation Whitesands Pilot Project”, Annual report to Alberta Energy Regulator, April 2012, https://www.aerca/documents/oilsands/insitu-presentations/2012AthabascaPetrobankWhitesands9770.pdf). At these low levels of oil production per well and high levels of air injection per barrel of oil produced, the process is not economically viable. An evolution of the original THAI concept is to install multiple vertical injection wells, in the so called MULTI-THAI process, to inject more air into the reservoir. However, field results are also not encouraging, as the process still relies on the injection of the oxidant via an immoveable vertical well, and hence the location and behaviour of the combustion front cannot be effectively controlled.
Another thermal recovery technique is the recently proposed combustion assisted gravity drainage (CAGD) process (H. Rahnema and D. D. Mamora, “Combustion Assisted Gravity Drainage (CAGD) Appears Promising”, Society of Petroleum Engineers, SPE Paper 135821, 2010; H. Rahnema, M. A. Barrufet, “Self-Sustained CAGD Combustion Front Development; Experimental and Numerical Observations”, Society of Petroleum Engineers, SPE Paper 154333, 2012; H. Rahnema, M. A. Barrufet and D. D. Mamora, “Experimental analysis of Combustion Assisted Gravity Drainage”, Journal of Petroleum Science and Engineering, v103, pp 85-95, 2013). In this process, pairs of horizontal wells are drilled into underground oil sands and heavy oil formations to develop a combustion chamber and combustion front in the formation, from the upper horizontal well, to mobilise warming and recovery of heavy oil from the lower horizontal wells.
The CAGD process shows promise when conducted in the laboratory (H. Rahnema, M. A. Barrufet, “Self-Sustained CAGD Combustion Front Development; Experimental and Numerical Observations”, Society of Petroleum Engineers, SPE Paper 154333, 2012; H. Rahnema, M. A. Barrufet and D. D. Mamora, “Experimental analysis of Combustion Assisted Gravity Drainage”, Journal of Petroleum Science and Engineering, v103, pp 85-95, 2013). However, the CAGD process has not been implemented in the field and the obvious potential drawbacks include: poor distribution of oxidant along the horizontal well, low oxidant flux into the formation, and the tendency of oxidant to preferentially bypass the reservoir in zones with high permeability (e.g., reservoir regions with fractures). These issues will lead to poor recovery of the oil from the reservoir and high operating costs, due to the inefficient use of the injected air/oxidant.
A thermal recovery technique widely used today is steam assisted gravity drainage (SAGD). In this process, pairs of horizontal wells are drilled into underground oil sands and heavy oil formations. Steam is then injected into the formation through the upper well to warm the heavy oil deposits, enabling hydrocarbons to flow out of the formation and into the lower well. From there, the hydrocarbons are lifted to the surface. However, the SAGD process has a number of drawbacks, including the generation of high CO2 emissions as a by-product of steam generation, and the need to manage large volumes of water. Typically 3 to 4 barrels of water must be handled for every barrel of oil produced. SAGD methods are most effective in relatively high-permeable reservoirs, and where the reservoir thickness is greater than 10 meters. However, many heavy oil formations are tight and thin, making them unattractive candidates for SAGD. As reservoir quality declines, the performance of SAGD also declines and the amount of water which needs to be handled increases, sometimes over 5 barrels of water per barrel of oil.
Additionally, as SAGD utilises the latent heat of steam to heat and mobilise oil, the preferred reservoir depth is typically between 250 and 500 meters, where sufficiently high SAGD operating pressures can be maintained. Shallow reservoirs with lower pressures cannot be operated at sufficiently high temperatures to effectively mobilise oil. In contrast, deep reservoirs with higher pressures require high temperature steam and risk excessive heat loss in the injection well, such that the steam quality is insufficient to efficiently mobilise oil once it enters the reservoir. Accordingly, the SAGD process is only a viable candidate for working a relatively small subset of the heavy oil reservoirs that exist.
Therefore, a need exits for improved methods for recovering heavy hydrocarbons from subterranean formations.